Oil, gas and geothermal wells are traditionally surveyed by electrical sensors or other tools lowered in a well bore by a cable with an inner copper conductor for powering the tools as well as providing a pathway to transmit data from the sensors. A typical cable will have an inner electrical conductor surrounded by multiple strands of steel armor. Such cables are costly, especially when built for use in corrosive environments, and they are difficult to build. Moreover, cables of known and conventional construction provide internal woven spiral interstitial paths through which gas and other corrosive elements hazardous to the environment can escape upwardly. Efforts to eliminate such leakage add further to the costs of sensing and are generally not entirely successful.
Fiber optic cable has been used in telecommunications for a number of years. Its main advantage over copper cable relates to "bandwidth" where a fiber cable can carry much more data or information. Technology has now progressed to a point where downhole sensors used in oil, gas or steam wells can generate so much information, that they can benefit from the additional bandwidth fiber optic cable can provide. A conventional copper cable is still necessary to provide a path for electricity to power down hole sensors.
In many cases, the well can also be quite deep, and the length of the down-hole instrument cable can exceed 15,000 feet. Longitudinal stresses placed on an optical fiber in such a long cable can sever or fracture the optical fiber, causing significant signal attenuation. Hence, the cable must be designed not only to resist physical damage to its outer surface from use in the well, and provide a robust fluid seal to protect the optical fiber and electrical conductors, but also to support the weight of the down-hole instrument and the cable itself.
Many wells are relatively small in diameter, on the order of 4.5 cm (1.75 in). Consequently the instrument probe and its cable designated for use in such a well are limited in their respective diameters. This can lead to practical problems when a high pressure well is involved. Such wells are capped to prevent the uncontrolled escape of high pressure well fluids and, in order to insert an instrument such as an electrical sensor in such a well, the instrument must be forced into the well through the cap. As is well known in the art, smaller instruments are easier to insert into a high pressure environment because they present less surface area against which the high pressure well fluids can act. High pressure well fluids oppose entry of the cable into the well and the cable must be made heavy enough to overcome the fluid pressure force. Also, it has been found that small differences in the diameters of down-hole instrument cables can have a tremendous impact on the ease and expense in inserting a cable and an attached instrument into the well.
As taught in U.S. Pat. No. 5,493,626 to Schultz, et al, a well pressure of 281 kg/cm.sup.2 (4000 psi), a cable with a 1.11 cm (7/16 in (0.438)) diameter will require the addition of 295 kg (650 lbs) additional weight to overcome the force against it created by the well fluid pressure to enter the well. One common technique for adding that weight is to attach sinker bars to the cable. The diameter of the well limits the diameter of the sinker bars requiring a longitudinal distribution of the weight along the cable. In a 4.5 cm (1.75 in) diameter well, sinker bars having the standard outside diameter of 3.5 cm (1.375 in) would be used. Even if using high density tungsten weights, each bar would be 1.8 meters (6 ft) long and have a weight of 20.4 kg (45 lbs). This would result in the need for 15 sinker bars placed end to end on the cable, and at 1.8 m (6 ft) each, a total length of 27.4 m (90 ft) of sinker bars results, adding this length to the length of the instrument itself, which may be 4.5 meters (15 ft), resulting in a total length of 31.9 meters (105 ft) for the complete assembly.
The cable must be raised above the well head and inserted through a pressure gland through lubricator risers, and past the main valve. In this case with such a long length of weights, an extended crane would be required to lift the assembly of instrument, cable, and sinker bars over the main valve of the well head and the specially attached lubricator risers attached to the well head to accommodate the assembly. It has been found in some cases that the expense involved in supporting such a long length of lubricator risers rises, the need for high crane heights, and the amount of time involved in assembling and disassembling outweigh the advantage that would be provided by down-hole monitoring.
Also as shown in the '626 patent, a cable having a diameter of 0.55 cm (7/32 in (0.218)) (approximately half the cable diameter of the prior art) and in a well having the same pressure of 281 kg/cm.sup.2 (4000 psi), the weight required to overcome the fluid pressure and insert the cable into the well is only 77 kg (170 pounds), which is approximately one fourth of the weight required for a cable twice its size. Using the same tungsten weight bars as described above, only four are required and at 1.8 meters (6 ft) each, the total length of the lubricating risers needed to accommodate the weights and the instrument is 12 meters (39 ft). It is clear that small changes in cable diameter result in much larger changes in weight requirements. Hence those concerned with high pressure wells have recognized the substantial effect that cable diameter has and have recognized the need for a reduced diameter cable so that insertion into high pressure wells is facilitated and made less expensive. Another consideration in cable design is the impact of the cable length on the size of the internal cable components. In the case of a coaxial cable, the longer the cable, the larger the cable diameter must be to support needed data transmission parameters for pressure, temperature and real-time video monitoring. It has been found that optical fibers are not as sensitive as coaxial cable to long distances and have large band-widths capable of supporting both monitoring and real-time video imaging. The use of fiber optics enables use of a much smaller diameter cable.
Distributed Temperature Sensing (DTS) is a method of monitoring temperature along a well bore. DTS uses a fiber optic cable as the temperature sensor. The fiber optic cable is installed along the full length of a well. A laser may then be attached to the end of the fiber that protrudes from the well at the surface. A laser beam excites the atoms of the fiber. The stimulated atoms send back a light pulse whose frequency is shifted due to the temperature of the atoms along the fiber. The laser system, through systematic pulses, can monitor temperature along the entire length of the fiber. Hence, the optic fiber becomes a temperature sensor, permitting the reading of the temperature gradients and changes along the well path.
However, the fiber optic cables that have been used for this purpose can not withstand exposure to well bore fluids that can cause damage to or disintegration of the fiber. Hermetically sealed coatings have been added to provide this protection, but existing cable with such coatings are expensive to build, do not account for the differing thermal expansion properties of the components of the cables, nor are such cables effective to inhibit the release of harmful gases which may escape from the well bore because of the woven and/or braided cable used to protect the cable.
One example of a cable that has been used in DTS systems is described in the '626 patent. An optical fiber is surrounded by a protective buffer layer and a protective gel and is inserted in a thin walled stainless steel tubing. The optic cable and buffer layer is then sealed within the stainless steel tubing, and the steel tubing is then covered by a copper wire netting, or mesh. The copper mesh provides a path for the electrical current used to power a down hole logging tool and/or light source. The combination of fiber optic cable, steel tubing and wire mesh is then encapsulated in a plastic layer of polyurethane insulation.
A first layer of spring steel armor wire is helically wound around the outer surface of the polyurethane insulation, and a second layer of spring steel armor wire helically wound in the opposite direction around the outer surface of the first layer of spring steel armor. The first and second layers of spring steel armor wire protect the fiber optic cable and electrical conducting mesh from physical damage in the borehole and to add tensile strength to enable pulling the cable, and any instrumentation suspended from such cable, from the well bore.
However, this cable design has inherent problems because of the numerous separate strands comprising the mesh that serves as a protective surface for cable. Typically, when employing the cable in a well bore, any braided cable is run through several narrow flow tubes, each about 6" long, that have a small hole down the center. The inside diameter of the hole is only several thousandths of an inch larger that the outer diameter of the cable. Such a design still permits the release of oil or gas from any well under high pressure. It is therefore common practice to seal, or "pack off," this escape route by injecting a thick, heavy grease in the space between the flow tube and the cable, as well as any gaps between the strands. This grease injection process is labor intensive and unreliable.
Additionally, since the mesh of the '626 patent includes two layers of wire wound in helically opposite directions, it is extremely difficult to sealingly pack off the first layer, thus providing a possible path for harmful oil and/or gas release through the interstitial gaps of the helically woven wire. And since the outside surface of the cable is comprised of wire strands, the strands under friction, tension and tensile forces can break or become deformed, resulting in wire projections and/or bunching of wires, commonly called a "birdcage," around the cable which then binds the cable in the flow tubes, thereby significantly increasing the amount of force necessary to remove the cable from the well bore, and thereby increasing the opportunity for damage to the fiber optics in the cable. If such "birdcaged" cable is abandoned in the well bore, additional costs are incurred.